For an oil field, the total daily oil production from the entire field is typically accurately metered for fiscal reasons, however, the production from individual oil wells is not known on a daily basis.
Typically, in an oil field, all oil wells are hooked up to a common production manifold which directs the commingled flow of water, oil and gas from the wells to a number of separators, each operating at distinct pressure and temperature. Thus, oil from numerous different wells is directed to the common production manifold and processed as one commingled flow, irrespective of well origination and thus no information on flow from individual wells is obtainable at the processing stage.
Many oil fields are also equipped with a test separator to which each of the wells can be routed individually to extract information about the present production state of the well being tested. The test results may provide information about well production and may provide input to pipeline simulation models, which are used to simulate the flow in the pipelines and which may be used to simulate different control structures for example to monitor, suppress or control slugging in multiphase fluid flow in pipelines.
Slug flow is a commonly observed pattern in multiphase fluid flow and is characterised as a flow regime with large coherent disturbances which cause large pressure fluctuations and variations in the flow rate which can affect process equipment, may damage the reservoir rock and imposes additional wear on the surface equipment, and which may even overload the capacity of the equipment at the pipeline outlet.
Therefore, simulation tools are often used to characterise the flow and attempt to control or suppress the slug flow, for example by regulating choke settings for the well in accordance with the simulation data. The simulation models typically require input from the well testing to provide reliable results.
Thus, other ways to monitor the wells have been suggested. In U.S. Pat. No. 8,078,328, wellhead pressure data are measured to form an isobaric pressure map of one or more reservoirs and displaying the at least one isobaric pressure map on a display to provide for real-time reservoir pressure monitoring. The pressure map may be overlaid with for example injection rate and cumulative injection for the well and on the basis of this a static reservoir pressure may be estimated.
Furthermore, instrumentation, such as multi-phase meters, can be positioned in the wells to provide some real-time information on actual well performance, and for example in EP 1588022, it is suggested to use a densitometer in the well to define the slug based on the measured density. It is further suggested to enhance the densitometer with further instrumentation to register the differential pressure (dP) between the slug detector and the process arrival to provide information on the on-line water cut in combination with the local hold-up or void fraction as well as fluid velocities of the different phases to thereby provide an indication of well performance.
However, such meters require regular maintenance and frequent calibration against test separator data to provide reliable information; testing of a well can only provide for real-time information on well performance for one well at a given point in time, thus other or additional solutions are needed.